The present invention concerns a process for oil recovery by tenside flooding.
In the extraction of oil from oil-bearing deposits, it is generally possible only to recover a fraction of the oil originally present by means of primary extraction methods. In these procedures, the oil reaches the surface due to the natural reservoir pressure. In secondary oil recovery, water is forced into one or several injection wells of the formation, and the oil is driven to one or several production wells and thereafter brought to the surface. This so-called water flooding as a secondary measure is relatively inexpensive; accordingly, it is frequently employed, but leads in many cases to only a minor increase in oil extraction from the deposit.
A more effective displacement of the oil can be accomplished by tertiary measures. These are more expensive but still urgently necessary from the viewpoint of national economies because of the present scarcity of petroleum. Such processes are those wherein either the viscosity of the oil is reduced and/or the viscosity of the flooding water is increased and/or the interfacial tension between water and oil is lowered. Most of these processes can be classified as solution or mixture flooding, thermal oil recovery methods, tenside or polymer flooding and/or as combinations of several of the aforementioned methods.
Thermal recovery methods include the injection of steam or hot water and/or take place via in situ combustion. Solution or mixture processes inject a solvent for the petroleum into the deposit. The solvent can be a gas and/or a liquid.
Tenside flooding processes are based primarily on a strong lowering of interfacial tension between oil and flooding water. Depending on the tenside concentration and in some cases on the type of tenside and additives, these are termed tenside-supported water flooding, customary tenside flooding (low-tension flooding), micellar flooding, and emulsion flooding. However, in some instances, especially in the presence of relatively high tenside concentrations, water-in-oil dispersions are produced. As compared with the oil, these have a markedly increased viscosity. In such cases, the tenside flooding step also aims to reduce the mobility ratio whereby the degree of efficiency of oil displacement is raised. Pure polymer flooding is based predominantly on the last-described effect of a more favorable mobility ratio between the oil and the pursuing flooding water.
Heretofore, organic sulfonates, such as alkyl, alkylaryl, or petroleum sulfonates, have been primarily disclosed as oil-mobilizing tensides. However, these materials possess a very low tolerance limit with respect to the salinity of the deposit waters. Salt concentrations of as low as 1,000 ppm are considered problematic, the sensitivity of these tensides to alkaline earth metal ions being especially pronounced. For these, the upper critical limit concentration is assumed to be about 500 ppm (U.S. Pat. No. 4,110,228). When using these tensides, precipitation products are formed in the presence of higher salt concentrations. These are apt to clog the formation. However, since many deposit waters possess substantially higher salinities, for example in Northern Germany up to 250,000 ppm, methods have been sought for exploiting the otherwise good oil-mobilizing properties of the organic sulfonates for higher-salinity formation systems as well. In admixture with co-surfactants, such as alcohols or nonionic tensides, organic sulfonates do show lower electrolyte sensitivity, but in most cases the oil-mobilizing activity was likewise reduced.
In contrast to this class of compounds, alkyl or alkylaryl polyglycol ether sulfates or carboxymethylated alkyl or alkylaryl ethoxylates show good compatibility even at extremely high salinities (for example, 250,000 ppm) of the formation waters. Since the oil-mobilizing effect of these tensides is good (H. J. Neumann, "DGMK BERICHTE" [DGMK Reports], Report 164 [1978]; D. Balzer and K. Kosswig, Tenside Detergents 16: 256 [1979] whose disclosures are incorporated by reference herein) and their manufacture is simple and economical, these classes of compounds are very well suited for use in oil displacement in medium- and high-salinity deposit systems (10,000-250,000 ppm total salt content).
In numerous investigations on the nature of residual oil mobilization in model formations using carboxymethylated ethoxylates as the tensides, it has been observed, however, that the transport of the oil bank through the formation is accompanied by a strong pressure rise. Thus, even in the case of relatively highly permeable artificial formations, pressure gradients were observed of up to about 40 bar/m. When transposed into field conditions, these lead to pressures far above the petrostatic pressure. This effect is apt to exclude the use of these tensides in tertiary petroleum recovery.
The literature likewise discloses pressure gradients of a similar magnitude (C. Marx, H. Murtada, M. Burkowsky, "Erdoel Erdgas Zeitschrift" [Petroleum-Natural Gas News] 93: 303 [1977]). These authors explain the high pressure differences by the formation of emulsion zones which, however, are said to be limited to the region of the flooding front. In in-house experiments, however, a local limitation of the pressure gradient could not be observed. Inasmuch as crude oil emulsions, stabilized by carboxymethylated ethoxylates, are structurally viscous, the high pressure differences also cannot be arbitrarily lowered by reducing the flooding velocity. Consequently, one would have to expect uncontrollably high pressure gradients in tenside flooding with carboxymethylated ethoxylates in a field test.
Therefore, attempts have been made to find a tenside flooding method based on the highly oil-mobilizing carboxymethylated ethoxylates but which does not produce high pressure gradients. Lowering of the pressure gradient is possible by achieving a greatly delayed tenside breakthrough by suitable adaptation of the amount of tenside to the deposit. However, this mode of operation presupposes homogeneous formations. Although these might occur in artificial sand piles, they hardly occur in actual deposits. Therefore, a solution to this problem is really not possible in this way.